Process for removing and recovering H2S from a gas stream by cyclic adsorption

ABSTRACT

A process for altering the composition of a feed gas containing H 2 S equivalents is disclosed. The process comprises (a) contacting the feed gas with a solid adsorbent at a temperature of 250-500° C., to obtain a loaded adsorbent, (b) purging the loaded adsorbent with a purge gas comprising steam, thus producing a product stream which typically contains substantially equal levels of CO 2  and H 2 S. The process further comprises a step (c) of regenerating the purged adsorbent by removal of water. The adsorbent comprises alumina and one or more alkali metals, such as potassium oxides, hydroxide or the like.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is the National Phase of International Patent Application No. PCT/EP2015/076151, Nov. 10,2015, published on May 19, 2016 as WO 2016/075109A1, which claims priority to Netherlands Patent Application No. 2013759, filed Nov. 10, 2014. The contents of these applications are herein incorporated by reference in their entirety.

The present invention is in the field of removal of sour gases by adsorption, for example from syngas or Claus tail gas. Thus, the invention relates to an improved process for the selective removal of hydrogen sulphide (H₂S), and optionally further inorganic sulphide components such as carbonyl sulphide (COS) and carbon disulphide CS₂, from a gas stream by adsorption, particularly a gas stream comprising CO₂ and H₂S in a molar ratio above 0.5, and for recovering the inorganic sulphur as H₂S allowing valorisation thereof.

BACKGROUND

Hydrogen sulphide removal from sour gas streams is of great industrial importance, as such gases are the main known source of H₂S. An important source of sour gases is synthesis gas (syngas) containing hydrogen, carbon monoxide, carbon dioxide and further components including H₂S, or its subsequent product obtained by water gas shift (WGS) reaction, such as described in WO 2010/059052. The WGS reaction produces H₂ and CO₂ while H₂S can be present in the feed stream. In Sorbent-enhanced WGS, CO₂ and H₂S are adsorbed onto an adsorbent such as alkali-promoted hydrotalcite and subsequently simultaneously desorbed from the adsorbent. As such, CO₂ and H₂S end up in the same effluent stream, restricting efficient reuse or requiring purification of such gaseous mixtures.

Known techniques for selective removal of H₂S from a sour gas containing CO₂ include physical, chemical and hybrid scrubbing techniques and metal oxide scavenging. Chemical scrubbing involves the use of amine-based solvents that chemically react with sour gases such as H₂S and CO₂. Physical solvents involve e.g. methanol or glycol, using the physical dissolution of the acid gases obeying Henry's law, and hybrid solvents combining the best of both chemical and physical solvents. Because these solvents favour H₂S over CO₂ only slightly, H₂S enrichment yields are relatively poor, which renders this technique unsuitable for selective removal of H₂S from a CO₂-rich, H₂S-lean stream.

EP2407227 provides a method for separating H₂S from a sour syngas stream different from the aforementioned liquid absorption processes using a pressure swing adsorption system (PSA) to produce a stream enriched in CO₂ and H₂S, after which H₂S is removed for instance by using a packed bed of ZnO that would be disposed of and replaced when saturated with H₂S, or silica gels, impregnated activated carbons and/or molecular sieves. In one embodiment, steam is used to heat the bed that has been loaded with H₂S to help removing said H₂S. Scavengers, such as Zn-, Zn/Cu- or Fe-based scavengers, bind H₂S irreversibly and thus cannot economically deal with feeds comprising relatively high amounts of H₂S, such as typically 200 ppm H₂S or even only 100 ppm H₂S. Large scale processes or H₂S levels above about 100 ppm require frequent replacement of the scavenger bed, which is usually too expensive to be economically feasible.

WO 2013/019116 discloses a process for selectively removing acidic gaseous components, in particular carbon dioxide (CO₂) and hydrogen sulphide (H₂S), from an adsorbent which has adsorbed these gaseous components from a feed gas. It involves a CO₂ purge to replace the H₂S and a subsequent H₂O purge to remove the CO₂. The process is well suited for a Sorption-Enhanced WGS process, which produces H₂ and CO₂, and wherein (small) amounts of H₂S may be present. H₂S and CO₂ are subsequently separately separated from H₂.

There remains a need for enriching a gaseous stream in H₂S from a (CO₂-rich, H₂S-lean) feed stream that comprises intermediate amounts of H₂S (e.g. 100-10,000 ppm), for which scavenger and scrubbing techniques are unsuited. Existing H₂S enrichment techniques as described above can only achieve about one order of magnitude enrichment at high H₂S concentrations, and two orders of magnitude increase in concentration from low H₂S concentrations, for which a marked improvement is required.

SUMMARY OF THE INVENTION

The invention relates to a process for contacting a feed gas comprising H₂S and CO₂ to an adsorbent material for altering the composition of the gas, and is particularly suited for selectively removing H₂S from a feed gas which is preferably CO₂-rich and H₂S-lean, as defined further below, or in other words for enriching such feed in H₂S. At the same time, a CO₂-containing stream may be produced which is low in H₂S. In the process of the invention, H₂S equivalents, including H₂S, carbonyl sulphide (COS) and carbon disulphide (CS₂), are preferentially adsorbed onto the sorbent, followed by purging the adsorbent with a purging gas comprising steam, which gives rise to desorption of H₂S. In view of such effective desorption with steam, intermediate CO₂ rinses are rendered superfluous.

The process according to the invention is thus capable of selectively removing hydrogen sulphide from a gas and of realising up to three orders of magnitudes H₂S concentration increase compared to the feed stream. To that end, the inventors found that selective retention of H₂S (and/or equivalents thereof) could be improved by conditioning the water concentrations at contact between feed gas and solid adsorbent for selectively adsorbing H₂S (and/or equivalents thereof). This can be achieved by either drying the solid adsorbent or providing a gaseous feed low in H₂O, or, preferably, both.

The process according to the invention thus comprises:

-   (a) contacting a feed gas containing H₂S equivalents, CO₂ and     optionally H₂O, wherein the molar ratio of H₂O to H₂S equivalents is     within the range of 0-(5+X), with a solid adsorbent at elevated     temperature, to obtain a loaded adsorbent and a first product gas; -   (b) purging the loaded adsorbent with a purge gas comprising steam     to obtain a second product gas.

Herein, the feed gas and/or the purge gas comprises a reducing agent such as hydrogen and the adsorbent comprises alumina and one or more alkali metals. In the molar ratio of H₂O to H₂S equivalents, which is in the range of 0-(5+X), X is defined as:

$X = {\sum\frac{n_{i} \times \left\lbrack {H_{2}S\mspace{14mu}{equivalent}} \right\rbrack_{i}}{\left\lbrack {H_{2}S{\mspace{11mu}\;}{equivalents}} \right\rbrack}}$ wherein [H₂S equivalents] indicates the total concentration (typically in ppm) of H₂S equivalents, [H₂S equivalent]_(i) indicates the concentration (typically in ppm) of a particular H₂S equivalent i and n_(i) indicates the amount of water molecules n consumed when said H₂S equivalent i is converted to H₂S.

The term “H₂S equivalents” as used herein denotes H₂S and its gaseous or volatile sulphur equivalents which contain sulphur (formally) in oxidation state −2, such as carbonyl sulphide (COS) and carbon disulphide (CS₂). H₂S equivalents are preferably selected from the group consisting of H₂S, COS, CS₂ and mixtures thereof. In this respect, COS and CS₂ are referred to as equivalents of H₂S. The term “H₂S equivalents” does not includes higher valence sulphur species such as sulphur dioxide

Preferably, the process comprises a further step (c) wherein the purged adsorbent is dried, after which the adsorbent is capable of adsorbing H₂S equivalents again. As such, the adsorbent is regenerated and available for reuse in step (a) of the process again. The terms “adsorbent drying” and “adsorbent regeneration” are used interchangeably.

It was found that, advantageously, carbonyl sulphide (COS) and carbon disulphide (CS₂), if present in the feed gas, are removed together with the H₂S when using the adsorbent of the present invention, not requiring a prior hydrolysis to H₂S of these components. With the purging of step (b), all original H₂S equivalents (H₂S, COS and CS₂ and the like) are released essentially as H₂S only. The H₂S enriched effluent (second product gas) is extraordinarily high in H₂S content, thus rendering the effluent useful for further application in e.g. Claus sulphur production.

DETAILED DESCRIPTION

The invention relates in a first aspect to a process for altering the composition of a gas containing H₂S equivalents and CO₂. In a second aspect, the invention relates to a Claus process wherein the process according to the first aspect is implemented. A third aspect of the invention concerns a system designed to implement the processes according to the first and second aspects of the invention, comprising a Claus unit and an adsorption module equipped with a bed of adsorbent comprising alumina and one or more alkali metals.

Process for Altering the Composition of a Gas

The first aspect of the invention more specifically relates to a process for selectively recovering H₂S from a feed gas or enriching said gas in H₂S, wherein said feed gas comprises CO₂ and H₂S equivalents, preferably in a molar ratio of H₂S equivalents to CO₂ of less than 2, and optionally water, wherein the molar ratio of H₂O to H₂S equivalents is in the range of 0-(5+X). The process comprises (a) contacting the feed gas with a solid adsorbent, at a temperature of 250-500° C., to obtain a loaded adsorbent (the loading including H₂S) and a purified first product gas, (b) purging the loaded adsorbent with a purge gas comprising steam to obtain a gas enriched in H₂S compared to the feed gas, and preferably (c) drying the purged adsorbent. The adsorbent comprises alumina and one or more alkali metals. The alkali metals are in particular in the form of their oxides, hydroxides, carbonates, sulphides, hydrosulphides, hydroxyl-carbonates, thiols, formates, hydroxyformates or the like, the (hydro)sulphides possibly being formed in the course of the adsorption process.

In the context of the present invention, the composition of gaseous mixtures is given in percentages (%) or ppm values. Unless indicated otherwise, these always refer to mole percentages or molar ratios. In the context of the invention, the term “gas” refers to any pure compound or mixture of compounds in the gas phase. A gas should be gaseous at the processing conditions, i.e. at least at a temperature of 250-500° C. and at a pressure of 1-15 bar, even though higher or lower pressures may be feasible as well. Under such conditions, water is in gaseous form, which may also be referred to as steam. Hence, the terms “water” (or “H₂O”) and “steam” are used interchangeably in the context of the present invention. Solid compositions, such as for the adsorbent, are typically given in wt % (weight percentage) unless indicated otherwise. The adsorbent is solid at the processing conditions.

The feed gas may be referred to as “sour gas”, which is a term of art for a gas containing at least 4 ppm hydrogen sulphide and/or equivalents thereof (see e.g. http://naturalgas.org/naturalgas/processing-ng/). Sour gases may be natural gases or may for example be generated during industrial processes (e.g. gasification of coal, biomass or mixtures thereof, e.g. the tail gas of a Claus process). The “sour gas” in the context of the invention contains H₂S equivalents, CO₂ and optionally water (steam). However, large amounts of water hamper selective adsorption of H₂S equivalents to the adsorbent, so water should be present in the feed stream in a molar ratio of H₂O to H₂S equivalents in the range of 0 to (5+X), preferably 0 to (2+X), even more preferably 0 to (1+X), most preferably 0 to 1. Herein, X is a constant, the value of which depends on the type and amount of equivalents of H₂S present in the feed gas, taking into account the consumption of H₂O during conversion of such equivalent to H₂S. Each equivalent of H₂S allows for a different maximal steam content. X is further defined below. Herein, a molar ratio of 0 (zero) refers to the complete absence of steam. In absolute terms, the water (steam) level in the feed gas is preferably below 20%, more preferably below 5%, even more preferably below 2%, most preferably below 0.5%. Although it is preferred that the feed gas is completely dry without any water present, the process according to the first aspect of the invention runs sufficiently effective even when a minor amount of water is present. Typically, the molar ratio of H₂O to H₂S equivalents may be at least 0.001 or at least 0.01 or at least 0.1 or even at least 0.5, or in absolute terms, the feed gas may contain at least 50 ppm water or at least 100 ppm water or even at least 500 ppm water. This implies that source gases containing appreciable levels of water, such as Claus tail gases, may have to be dried, e.g. by condensation, adsorption, absorption or other conventional methods, to below the above levels, before being subjected to the process of the invention.

The feed gas comprises H₂S equivalents as defined herein. In the context of the present invention, the term “H₂S equivalents” denotes H₂S and its gaseous or volatile sulphur equivalents which contain sulphur (formally) in oxidation state −2, such as carbonyl sulphide (COS) and carbon disulphide (CS₂). H₂S equivalents preferably comprise H₂S, COS and/or CS₂, more preferably are selected from the group consisting of H₂S, COS, CS₂ and mixtures thereof. In this respect, COS and CS₂ are referred to as equivalents of H₂S. The term “H₂S equivalents” does not include higher valence sulphur species such as sulphur dioxide. Typically, but not mandatorily, the H₂S equivalents include H₂S as such, and preferably, they also include COS and/or CS₂. The combined content of H₂S equivalents in the feed gas typically ranges from 5 ppm to 5% (50,000 ppm), preferably 10-25,000 ppm (2.5%), more preferably 100-10,000 ppm, even more preferably 150-5000 ppm, most preferably 200-2000 ppm. It is noted that COS and CS₂ were found to be adsorbed in step (a) and converted to H₂S upon steam purging of step (b). Regardless of the type of H₂S equivalent(s) present in the feed gas, the second product stream, i.e. the effluent of step (b), will contain H₂S as sole sulphur species. COS and CS₂, as well as H₂S itself, are desorbed as H₂S. These species are thus considered equivalent to H₂S.

Without being bound to a theory, it is expected that during the operating conditions, two equilibria are established for which the adsorbent acts as a catalyst. These two equilibria are: COS+H₂O

H₂S+CO₂   (1) CS₂+2H₂O

2H₂S+CO₂   (2) Upon breakthrough, i.e. complete loading of the adsorbent with H₂S equivalents, H₂S equivalents end up in the first product gas, since they can no longer be adsorbed. The inventors found that regardless of whether H₂S, COS or CS₂ (or mixture thereof in any ratio) is present in the feed gas, H₂S and COS are observed in the first product gas in their equilibrium concentrations according to equilibrium (1). No CS₂ is observed, since equilibrium (2) is completely shifted to the right under the processing conditions, i.e. equilibrium concentration of CS₂ is (close to) 0.

As is clear from equilibrium (1), one molecule of COS is equivalent to one molecule of H₂S, wherein one molecule of H₂O is consumed. Thus, for each molecule (or mole) of COS present in the feed stream, one additional molecule (or mole) of H₂O may be present therein. Likewise, as is clear from equilibrium (2), one molecule of CS₂ is equivalent to two molecules of H₂S, wherein two molecules of H₂O are consumed. Thus, for each molecule (or mole) of CS₂ present in the feed stream, two additional molecules (or moles) of H₂O may be present therein. For this reason, the allowable water content in the feed gas employs the factor X. Thus, the ratio of H₂O to H₂S equivalents is in the range of 0-(5+X), preferably 0-(2+X), even more preferably 0-(1+X), wherein X is defined as:

$X = {\sum\frac{n_{i} \times \left\lbrack {H_{2}S\mspace{14mu}{equivalent}} \right\rbrack_{i}}{\left\lbrack {H_{2}S{\mspace{11mu}\;}{equivalents}} \right\rbrack}}$ Herein, [H₂S equivalents] indicates the total concentration (typically in ppm) of H₂S equivalents, [H₂S equivalent]_(i) indicates the concentration (typically in ppm) of a particular H₂S equivalent i and n_(i) indicates the amount of water molecules n consumed when said H₂S equivalent i is converted to H₂S. Thus, n_(i)=0 for i=H₂S, n_(i)=1 for i=COS and n_(i)=2 for i=CS₂. For the preferred situation where the H₂S equivalents are selected from H₂S, COS, CS₂ and mixtures thereof, X simplifies as:

$X = \frac{\lbrack{COS}\rbrack + {2 \times \left\lbrack {CS}_{2} \right\rbrack}}{\left\lbrack {H_{2}S\mspace{14mu}{equivalents}} \right\rbrack}$ Herein, [COS] and [CS₂] indicate the concentration (typically in ppm) of COS and CS₂ respectively, and [H₂S equivalents]=[H₂S]+[COS]+[CS₂]. In case the H₂S equivalents only contain H₂S, i.e. the feed gas does not comprise detectable amounts of other H₂S equivalents, X=0. Since X defines the upper limit of the allowable range of H₂O to H₂S in the feed gas, X may not exceed the above-defined values, as that would render the feed gas too wet for effective performance of the process according to the first aspect of the invention. For example, one molecule of COS requires one molecule of H₂O (or consumes one molecule of H₂O) for conversion to one molecule of H₂S, so n_((COS))=1. Thus, when the feed gas comprises COS as the only H₂S equivalent, X=1 and the maximal allowable water content of the feed gas defined as the ratio of H₂O to H₂S equivalent is 6. Similarly, a 9 to 1 H₂S to COS mixture gives X=0.1 and results in a maximal allowable ratio of H₂O to H₂S equivalent of 5.1. Pure CS₂ gives X=2 and results in a maximal allowable ratio of H₂O to H₂S equivalent of 7. In one embodiment, X=0 and the H₂O to H₂S equivalents ratio is 0-5, preferably 0-2, more preferably 0-1.

The feed gas may also be referred to as a “CO₂-rich, H₂S-lean” feed gas, meaning that the molar ratio of H₂S equivalents to CO₂ is preferably below 1, more preferably below 0.1, even more preferably between 0.0001 and 0.05, most preferably in the range of 0.001-0.02 or even 0.002-0.01. CO₂ levels of the feed gas may vary greatly without negatively affecting the process. They typically range from 100 ppm to 99%, preferably at least 500 ppm and up to 95%, more preferably from 0.5% (5000 ppm) up to 50%, most preferably 3-25%.

In addition to the acidic or “sour” species, other, essentially non-acidic, components may also be present, including hydrogen, carbon monoxide, hydrocarbons or other fuel gases, water, as well as any amount of inert gaseous species such as nitrogen, noble gases (e.g. helium, argon) and the like. The level of oxygen should preferably be low, e.g. below 2%, preferably below 0.5% or even below 0.1% (1000 ppm). The presence of higher levels of O₂ is undesirable, as this creates an oxidizing environment wherein SO₂ may be formed. Thus, the presence of O₂ counteracts the effect of the reducing agent which is preferably present in the feed gas. As discussed, the water content should also be kept low.

The feed gas typically further comprises a reducing agent. Although less preferred, the feed gas could also be free of a reducing agent, in which case it might be required to periodically regenerate the bed of adsorbent material. Such bed regeneration could be effected by reduction using a reducing agent as defined herein, optionally assisted by heating the bed to aid the decomposition of deactivating components. The reducing agent in the context of the present invention is a gaseous species capable of reducing oxidised species, typically capable of preventing the oxidation of H₂S to SO₂ or sulphates, under the process conditions. During the purging of step (b), the adsorbed H₂S species are in contact with great excess of H₂O molecules, which may oxidise H₂S (and/or equivalents thereof) to SO₂ or even sulphates, under the process conditions. A reducing environment suppresses such oxidation. The inventors surprisingly found that the presence of a reducing agent in the feed gas, i.e. during the contacting of step (a), suppresses such oxidation during step (b). Alternatively, the purging gas may comprise the reducing agent, as described further below, which also suppresses such oxidation. If no reducing agent is present in both the feed gas and the purging gas, significant amounts of the adsorbed H₂S are converted to sulphates during step (b), which are not capable of desorbing from the adsorbent. Preferably, the reducing agent is selected from H₂ and/or CO, more preferably the feed gas comprises at least H₂ as reducing agent. The feed gas preferably comprises 0.1-50%, more preferably 0.5-30%, most preferably 1-20% reducing agent, most preferably H₂. The presence of a reducing agent thus suppresses the formation of sulphates on the adsorbent, for which the adsorbent may act as catalyst. The presence or formation of SO₂ is undesirable, since it is adsorbed during step (a) and when contacted with steam during step (b), SO₂ reacts to sulphate which is not readily desorbed upon purging with steam. Thus, the presence or formation of SO₂ and/or the absence of a reducing agent decreases the adsorption capacity of the adsorbent.

It is thus also preferred that the feed gas does not contain appreciable levels of SO₂ (or other sulphur oxides, together referred to as SO_(x)); preferably it contains less than 0.5% (5000 ppm), more preferably less than 0.05% (500 ppm), most preferably less than 50 ppm. In a particular embodiment, the feed gas contains substantially no (i.e. less than 10 ppm) of SO₂. In an especially preferred embodiment, the content of CO₂ and H₂ is substantially equal (ratio between 1:2 and 2:1). CO may also be present, e.g. in an amount of 0.05-30%, more preferably 0.1-20%, most preferably 0.5-10%. Since the feed gas preferably contains syngas, it is preferred that the level of H₂ and CO is substantially equal, i.e. molar ratio H₂:CO is 1:2-2:1.

According to a preferred embodiment of the invention the process is used for the separation H₂S from sour natural gas, syngas (e.g. general, biomass-derived or coal-derived), Claus tail gas, H₂S-containing gaseous fuels, tail gas of hydrodesulphurisation, wherein sulphur species are removed from gaseous streams (e.g. of petroleum products of refineries) by hydrogenation to H₂S. Such gases are preferably used as feed gas in step (a) of the process according to the invention. H₂S is readily separated from H₂S-containing gaseous fuels by the process according to the invention, wherein the fuel depleted in H₂S is obtained as first product gas. The adsorbent according to the invention does not adsorb hydrocarbon species, which thus leads to no loss in fuel during the adsorption of step (a). Amine scrubbing to remove sulphur species will always lead to some removal of hydrocarbons, thus leading to fuel loss. Preferred feed gases include H₂S-containing gaseous fuels, syngases and Claus tail gases, in particular, syngases and Claus tail gases having typical compositions as given in Table 1 below. Herein “inert” gases comprise nitrogen, noble gases and the like and the values for H₂S include COS and CS₂. Most preferably, a Claus tail gas is used as feed gas, since the process according to the first aspect of the invention is especially suitable to be incorporated with a Claus process. In this respect, it is especially preferred that the second product gas is used as incoming gas for a Claus process. These aspects of the invention are discussed further below.

In one embodiment, the feed gas has been pre-treated prior to being subjected to step (a) of the process according to the first aspect of the invention. Pre-treatment may be employed to lower the H₂O content and/or the SO₂ content (or the SO_(x) content). Pre-treatment to lower the SO₂ or SO_(x) content is particularly preferred for Claus tail gases and typically involves subjecting a SO_(x)-containing gas to a hydrogenation-hydrolysis step, as known to the art, to convert SO_(x) to H₂S. SO_(x) can also be lowered by scrubbing with an alkaline solution followed by chemical reduction, e.g. using hydrogen, or by biological reduction, e.g. using bacteria of the genera Desulfovibrio, Desulfobacterium, Desulforomonas or the like. Alternatively, the SO₂ or SO_(x) content of the Claus tail gas can be lowered by tuning of the oxidation step(s) in the Claus process itself.

Pre-treatment to lower the H₂O content is particularly preferred in case the H₂O content of a potential feed gas is too high, i.e. the molar ratio of H₂O to H₂S equivalents is above (5+X). Where necessary, the H₂O level of the feed gas is lowered e.g. by cooling and/or pressurisation resulting in condensation of water or by other conventional methods such as absorption or adsorption. Since drier feed gases give rise to increased H₂S adsorption capacity of the adsorbent, it is preferred that pre-treatment to lower the H₂O content includes a measure to lower the H₂O level to well below 1%. Such a measure may include a glycol rinse of the feed gas and/or contacting the feed gas with molecular sieves, optionally after one or more of the above-mentioned techniques. Alternatively or additionally, the H₂O content may be lowered by selective permeation of water through a membrane (e.g. by vacuum permeation). Feed gases pre-treated as such are especially suitable to be used as feed gas for the process according to the first aspect of the invention, in view of their extremely low or even negligible water content. Pre-treatment to lower the H₂O level is also referred to as drying or “pre-drying”.

TABLE 1 Typical gaseous compositions (in vol %) H₂ CO CO₂ H₂O CH₄ inert H₂S Syngas general 25-45 20-60 5-25 2-30 0-15 0.5-5  0.01-1  Biomass-derived 30-45 20-30 15-25  2-10 5-15 2-5  0.002-0.05 Coal-derived 25-30 30-60 5-15 2-30 0-5  0.5-5  0.2-1 Claus tail gas 0.2-5  0-1 1-10 15-50  0-1  40-75 0.5-5

The adsorbent to be used in the process of the invention is capable of adsorbing H₂S and comprises a mixture of inorganic (hydr)oxides comprising a trivalent metal oxide, especially alumina (aluminum oxide or hydroxide). Instead or in addition to aluminum, other metals capable of adopting a trivalent state may be present, such as Fe, Mn, Cr, Ti, Pd, Ce and Zr. Apart from being highly effective in the process according to the invention, the use of alumina in the adsorbent according to the invention has further advantages. First of all, aluminas are highly stable towards reducing condition that occur during the process according to the invention, in contrast to e.g. tin oxide based materials. Also the hydrothermal stability (i.e. the inertness towards steam at high temperature) of aluminas, especially hydrotalcites, is excellent, thus preventing sintering of the adsorbent material under the process conditions. Sintering is especially disadvantageous, since it reduces the surface area of the adsorbent and thus the adsorbent capacity. The alumina of the adsorbent according to the invention is promoted with, i.e. contains, one or more alkali metals, in ionic form, e.g. as their oxides, hydroxides, carbonates, or in situ, sulphides and/or hydrosulphides. Preferably the adsorbent comprises one or more alkali metal oxides, hydroxides and/or carbonates, more preferably one or more alkali metal oxides or carbonates. Any alkali metal can be used, including Li, Na, K, Rb and Cs. Preferred alkali metals are Na and K, most preferably K is used as alkali metal. The alkali metal content of the adsorbent is preferably 2-30 wt %, more preferably 5-25 wt %, most preferably 10-15 wt %.

The adsorbent may advantageously further comprise one or more divalent metal oxides, hydroxides, carbonates, sulphides and/or hydrosulphides. The divalent metals can be an alkaline earth metal (Mg, Ca, Sr, Ba) or Co, Ni, Cu, Zn, Cd, Pb. Preferred divalent metals are Mg, Ca, Sr, Ba, Zn, Ni and Cu. More preferably, the adsorbent comprises calcium oxide and/or magnesium oxide and/or zinc oxide. In particular, the adsorbent has an atomic ratio of divalent metals (especially one or more of Mg, Ca, Zn) to Al of between 0 and 3, preferably between 0.05 and 1.5, e.g. between 0.11 and 1.0, and an atomic ratio of alkali metal (especially Na and/or K) to Al of between 0.1 and 1.0, preferably between 0.15 and 0.75, most preferably between 0.25 and 0.5. Aluminas also containing alkali metals, possibly in addition to other metals and counter ions, are referred to herein as “alkali-promoted” aluminas. Alkali-promoted alumina, not containing divalent metals, are well suitable in the present process. A specific and preferred example of a suitable adsorbent is K-promoted alumina The K-promoted alumina preferably comprises 5-25 wt % K, more preferably 10-15 wt % K, based on total weight of the adsorbent.

When the adsorbent further comprises magnesium oxide (magnesia), it preferably has an atomic Mg to Al+Mg ratio of between 0.05 and 0.85, more preferably between 0.1 and 0.8, most preferably between 0.2 and 0.5. Aluminas that further comprise magnesia are referred to as “hydrotalcites”. Where reference is made to alumina, magnesia and the like, these include the oxides, but also hydroxides and other equivalents of the oxides of aluminum, magnesium, respectively. Herein, sulphides and hydrosulphides are considered equivalent with oxides and hydroxides respectively. It is envisioned that upon adsorption of sulphur species such as H₂S metal oxides and hydroxides present in the adsorbent are converted into sulphides and hydrosulphides. When present, metal sulphides and hydrosulphides are likely to be transformed to metal oxides and hydroxides. It is however preferred that at least metal oxides are present in the adsorbent. Magnesium is particularly preferred over e.g. zinc, for feed gas mixture containing high amounts of sulphur-containing species such as H₂S, since the magnesium-based adsorbents were found to be chemically relatively insensitive to the sulphur compounds, i.e. not be deteriorated in use.

Aluminas also containing magnesium and/or other divalent metals, and also containing alkali metals, possibly with other metals and counter ions, are referred to herein as “alkali-promoted hydrotalcites”. The aluminas may be used in a manner known per se, which may comprise admixing metals oxides and further additives with the alumina or hydrotalcite or other base material in a dry state or in a solution or a slurry, and optionally drying and calcining the resulting mixture. The alumina may be any form of alumina which can be rehydrated, in particular which has a level of hydroxyl groups. Examples include gamma-alumina, boehmite, gibbsite, bayerite.

The adsorbent to be used in the process according to the first aspect of the invention can be represented by the following chemical formula: [M^(II) _((1−x))Al_((αx))M^(III) _(((1−α)x))(OH)_(y)][Z^(n−)]_(((x−y+2)/n)).pH₂O.qM^(I)(A^(m−))_(1/m), wherein:

-   M^(I) is one or more metals selected from Li, Na, K, Rb and Cs,     preferably from Na and K; -   M^(II) is one or more metals selected from Mg, Ca, Sr, Ba, Co, Ni,     Cu, Zn, Cd and Pb, preferably from Mg, Ca, Ni, Cu and Zn; -   M^(III) is one or more metals selected from Fe, Mn, Cr, Ti and Zr; -   Z^(n−) is one or more anions selected from halide, nitrate or     acetate (n=1), or oxide, sulphate, oxalate or carbonate (n=2); -   A^(m−) is one or more anions selected from hydroxide (m=1) and the     anions as defined for Z above, with m corresponding to n; -   m and n=1 or 2, according to A and Z, respectively; -   x=0.05-1, preferably 0.1-1.0, more preferably 0.2-0.95, most     preferably 0.4-0.8; -   α=0-1, preferably 0.5-1, most preferably α=0.95-1; -   p=0-15; -   q=0.1-1; and -   y=0-4.

Specific examples of hydrotalcites of the above formula are referred to herein as KMG30 having an MgO:Al₂O₃ weight ratio of 30:70 and having the formula [Mg_(0.35)Al_(0.65)(OH)₂][CO₃ ²⁻]_(0.325).0.5H₂O.0.32K(CO₃ ²⁻)_(0.5) with a molar ratio K:Mg:Al of about 1.0:1.1:2.0 and a molar ratio of K:(Mg+Al) in the order of 1:3.1 (0.32:1); and as KMG70 having an MgO:Al₂O₃ weight ratio of 70:30 and having the formula [Mg_(0.74)Al_(0.26) (OH)₂][CO₃ ²⁻]_(0.13).0.5H₂O.0.27K(CO₃ ²⁻)_(0.5) with a molar ratio K:Mg:Al of about 1.0:2.7:0.9 and a molar ratio of K:(Mg+Al) in the order of 1:3.6 (0.27:1)

The anions in the complex metal oxides are as defined above. Preferably the adsorbent comprises hydroxide and/or carbonate anions in order to ensure sufficient alkalinity for an effective adsorption of acidic gas species. In particular, at least 50% of the anions (expressed in monovalent equivalents) consist of hydroxide and/or carbonate.

Suitable inorganic oxides can have a layered structure, wherein part of the anions is arranged in layers interposed between layers containing the cations. Examples of suitable layered oxides include the hydrotalcites having proportional formula's such as Mg₆Al₂(CO₃)(OH)₁₆.4(H₂O) or similar combinations with different Mg:Al ratios. Other suitable oxides include analogues wherein magnesium is absent (e.g. scarbroite) or is replaced by calcium (e.g. alumohydrocalcites), strontium (e.g. montroyalite) or barium (e.g. dreserrites), as well as Mg/Fe, Mg/Cr, Mg/Mn, Ni/Al, etc. analogues (pyroaurite, stichtite, desautelsite, takovite).

In a preferred embodiment, the adsorbent as prepared for step (a) of the process of the invention has a H₂O content of at most 5 wt %, based on the total weight of the adsorbent. In order to obtain such H₂O contents, it may be beneficial to dry the adsorbent prior to step (a). Methods and means for drying the adsorbent are known in the art and described further below in the context of the regeneration of step (c).

The adsorbent may have been thermally treated, i.e. it may have been heated at a temperature above about 200° C., even more especially above about 400° C. For instance, assuming a hydrotalcite adsorbent, when heating this hydrotalcite in the reactor before or during an adsorption-desorption reaction, the hydrotalcite modifies to a promoted alumina, such as K₂CO₃ and MgO promoted alumina, since at elevated temperatures, the hydrotalcites may at least partially rearrange in mixed oxides while losing hydrotalcite crystalline structure and layered double hydroxide structure. This is well known in the art and is for instance described in U.S. Pat. Nos. 5,358,701, 6,322,612 and WO 2005/102916.

During step (a) of the process according to the first aspect of the invention, the feed gas is contacted with the adsorbent at a temperature of 250-500° C., preferably of 280-450° C., more preferably 300-420° C. Step (a) is preferably performed at a pressure of below 15 bar, such as 1-15 bar, more preferably 1-10 bar, for a period of at least 5 minutes, such as 10 minutes—e.g. 12 h, preferably 30 minutes—8 h. The flow rate of the feed gas in step (a) may be e.g. 1-25 m³ per kg of sorbent per h, preferably 4-20 m³/kg/h. During the contacting, certain species, in particular acidic species, are adsorbed onto the adsorbent, while other species may pass through the adsorbent material without being adsorbed (“slip through”). Such non-adsorbed species typically included inert gases such as nitrogen, argon and hydrocarbons. Together, the non-adsorbed species form a first product gas, which is depleted in acidic species, particularly in H₂S equivalents, compared to the feed gas. The first product gas is thus the off-gas of step (a). Step (a) is preferably continued until breakthrough of H₂S equivalents commences, which end up as a mixture of H₂S and COS in the first product gas as explained above. It should be noted that the conditions during step (a) are typically such that no water gas shift reaction occurs.

The inventors surprisingly found that when the water content of the feed gas is sufficiently low, the adsorbent material according to the invention has an increased selectivity for H₂S (and/or equivalents thereof), when compared to adsorption by the same adsorbent with a “wet” feed gas, i.e. having a H₂O to H₂S equivalents molar ratio of above (5+X). With such a wet feed gas, the adsorbent adsorbs relatively large amounts of CO₂ while adsorbing comparatively low amounts of H₂S, e.g. as described in WO 2013/019116. Although the concentration of CO₂ of the feed gas is typically several factors higher than the concentration of H₂S equivalents in the feed stream, the molar ratio of H₂S (and/or equivalents thereof) to CO₂ that is adsorbed onto the adsorbent is surprisingly high, even above 1, when a dry feed gas is used. In this respect, it is irrelevant whether the equivalents of H₂S, typically COS and/or CS₂, are converted to H₂S when being in the gaseous state and subsequently adsorbed as H₂S, or that the equivalents of H₂S are first adsorbed as such and subsequently converted to H₂S. The sulphur species that is desorbed during step (b) is at all times H₂S, and the second product gas is substantially free of equivalents of H₂S such as COS and CS₂. Without being bound to a theory, it is believed that the adsorbent acts as catalyst for the conversion of the equivalents of H₂S to H₂S, and that the conversion occurs when an equivalent of H₂S is in adsorbed state. In the context of the present invention, reference is made to adsorption of H₂S equivalents.

The inventors found that increasing amounts of water in the feed gas decreases the selectivity for H₂S equivalents. As the amount of H₂S equivalents being adsorbed during step (a) decreases, the H₂S content in the second product gas, i.e. the off-gas of step (b), decreases. The H₂S content in the second product gas becomes unacceptably low when the ratio of H₂O to H₂S equivalents in the feed gas is above (5+X). The drier the feed gas the higher the capacity of the adsorbent for H₂S equivalents, thus it is preferred that the H₂O to H₂S equivalents ratio in the feed gas is 0 or close to 0. When the H₂O to H₂S equivalents ratio is in the range of 0-(5+X), preferably 0-(2+X), more preferably 0-(1+X), the sorbent capacity for CO₂ and H₂S equivalents is more or less similar, i.e. CO₂ to H₂S adsorption is 2:1-1:2, in step (a) of the process according to the first aspect of the invention. For completely dry feed gases, i.e. having a H₂O to H₂S equivalents ratio of 0 or close to 0, the ratio of CO₂ to H₂S being adsorbed in step (a) was as high as 1.5, which slightly decreased to 0.6 for a feed gas comprising H₂O and H₂S equivalents in a ratio of about 2. Such capacities for H₂S equivalents afford excellent second product gases in terms of H₂S content and H₂S to CO₂ ratios. H₂S capacities of the adsorbent were found acceptable for feed gases comprising water up to a H₂O to H₂S ratio of (5+X).

In view of the adsorption of H₂S equivalents during step (a), the first product gas, i.e. the gas issuing from step (a), is depleted in H₂S; it typically contains substantially no H₂S, i.e. less than 10 ppm, advantageously less than 5 ppm or even less than 1 ppm. The first product gas generally contains less than 0.1 times, preferably 0.05 times, most preferably less than 0.02 times the level of H₂S equivalents of the feed gas, and the level may be as low as 0.001 or even 0.0002 times the feed level. Alternatively, or additionally, the first product gas has a molar ratio H₂S equivalents to CO₂ of less than 0.005, preferably less than 0.002, down to e.g. 0.0001 or even 0.00001. When compared to the feed gas, the first product gas has an decreased ratio of H₂S equivalents to CO₂.

The first product gas may be emitted into the environment, which is acceptable in view of its negligible sulphur content, although incineration of the first product gas prior to emission may be desired in case it contains hydrocarbons, CO and/or H₂. In view of its low sulphur content and potentially high CO₂ content, depending on the CO₂ content of the incoming feed gas, the first product gas may also be suitable for carbon capture and storage (CCS). Alternatively, it may be used or further processed in any way conceivable, e.g. as a high-CO₂ source gas, fuel gas or syngas.

The contacting of step (a) may be performed by any means known in the art for contacting a gaseous stream with a solid material. Typically, a packed bed reactor is used, e.g. in the form of a column or tube wherein a tubular reactor is packed with the adsorbent material, although a fluidised bed may also be used. The stream of the feed gas is led over or through said reactor. In case a column is used, the feed gas is conveniently injected into the adsorbent, e.g. at the bottom or top of the column, and the first product gas is released, conveniently at the other side of the column. Alternative arrangements, including horizontal flows or flow entering and leaving the column at the long sides, are also well suitable. After contacting step (a), the adsorbent has been become loaded with acidic species, in particular H₂S and CO₂.

In step (b), the adsorbed molecules are desorbed from the adsorbent, by purging (rinsing) with a purging gas. The purging gas used in step (b) comprises steam, preferably the purging gas is steam, although minor amounts of other components such as N₂, Ar, H₂S or CO₂ may also be present in the purging gas. It is preferred that the content of other gases than steam and optionally inert gases is kept low. Preferably at least 75% of the purging gas is steam and optionally inert gas(es), more preferably at least 90%, most preferably at least 95% is steam and optionally inert gas(es). Typically, the ratio of steam to inert gas is in the range of 5/95-100/0, more preferably 20/80-100/0, even more preferably 50/50-100/0, most preferably 90/10-100/0. The CO₂ content is kept low, preferably below 0.1% (1000 ppm), especially below 100 ppm or even below 10 ppm. The presence of CO₂ is not required for effective desorption and only leads to a reduced H₂S content in the first effluent, compared to the CO₂ content (i.e. decreasing the H₂S/CO₂ molar ratio). It is also preferred to keep the H₂S content low in the purging gas, preferably 0-1%.

In one embodiment, the purging gas comprises a reducing agent. The type and content of the reducing agent comprised in the purging gas is typically the same as defined above for the feed gas. The presence of a reducing agent in the purging gas ensures that any adsorbed SO_(x) species is reduced to H₂S upon desorption. It is preferred that the feed gas comprises a reducing agent as defined above, and the purging gas is substantially free of reducing agent (i.e. comprises <1% reducing agent, especially below 100 ppm or even below 10 ppm). In an especially preferred embodiment, the purging gas is substantially pure steam, i.e. comprising at least 95% steam or even at least 99% steam or about 100% steam. Any further component, apart from steam, that is present in the purging gas reduces the H₂S and CO₂ content of the second product gas, based on dry weight. The potentially large amounts of water that are present in the second product gas are readily reduced by e.g. condensation. In an alternative embodiment, the purging gas is a Claus tail gas that has not been subjected to drying. The H₂O present in the Claus tail gas enables desorption of H₂S, thus giving rise to a Claus tail gas enriched in H₂S as second product gas.

The temperature at which step (b) is performed preferably ranges from 250-500° C., more preferably 300-450° C. Step (b) is preferably performed at a pressure of below 15 bar, such as 1-15 bar, more preferably 1-10 bar, for a period of between 10 minutes and e.g. 48 h, preferably between 20 minutes and 24 h. The flow rate of the purge gas in step (b) may be similar to the flow rate of step (a), e.g. 1 to 25 m³ per kg of sorbent per h, preferably 4-20 m³/kg/h. Although the temperatures and pressures employed in steps (a) and (b) may vary, the process is advantageously performed with steps (a) and (b) at about the same temperature and pressure. Thus, any difference in temperature between step (a) and step (b) is preferably less than 50° C., more preferably less than 20° C., and any difference in pressure between step (a) and step (b) is preferably less than 50%, more preferably less than 25%, or less than 1 bar. In other words, no pressure swing (i.e. a cycle comprising relatively high-pressure adsorption and relatively low-pressure desorption) or temperature swing (i.e. a cycle comprising relatively low-temperature adsorption and relatively high-temperature desorption) is required to obtain H₂S enrichment according to the present invention. Step (b) may be performed in co-current mode or counter-current mode with respect to adsorption step (a). For optimised desorption, it is preferred that step (b) is performed in counter-current mode with respect to step (a).

In a preferred embodiment, the process according to the first aspect of the invention runs in parallel, i.e. at least two reactor beds comprising the adsorbent according to the invention, preferably in separate reactors, are used simultaneously, one is performing step (a), i.e. is being fed with the feed gas and expels the first product gas, and the other one is performing step (b), i.e. is being fed with the purge gas and expels the second product gas. Preferably, the bed operating in step (b) subsequently performs step (c), as described below, before the beds are switched and the now loaded bed is subjected to step (b) and the now purged and preferably dried bed is subjected to step (a). Alternatively, a third bed may be used, which is subjected to step (c) while a first bed is being subjected to step (a) and a second bed is being subjected to step (b). In this embodiment, the two, three or more beds operate according to the cyclic scheme of step (a)→step (b)→step (c)→step (a)→etc.

During purging with a purging gas comprising steam, water molecules occupy adsorption sites on the adsorbent, thereby releasing the acidic species such as H₂S, CO₂ that were adsorbed during step (a). These desorbed species, together with a large part of purging gas that is not adsorbed, make up a second product gas stream (effluent). The second product gas is a main product of the process according to the first aspect of the invention, and is enriched in H₂S compared to the feed gas. Here, “enrichment” refers to the increased content of H₂S (based on dry weight) compared to the content of H₂S equivalents in the feed gas (based on dry weight) and/or to the increased molar ratio of H₂S (and/or equivalents thereof) to CO₂ compared to the feed gas. It should be noted that the second product gas is substantially free of equivalents of H₂S, since all sulphur species that are adsorbed during step (a) are desorbed as H₂S during step (b). When compared to the feed gas, the second product gas has an increased ratio of H₂S equivalents to CO₂. The molar ratio of H₂S to CO₂ in the second product gas is typically increased to between about 1 and about 2, whereas the H₂S equivalents to CO₂ molar ratio in the feed gas may be as low as 0.001 or even lower. As such, an enrichment up to three orders of magnitude may be achieved, which is unprecedented in the art.

The second product gas typically contains H₂S, CO₂ and H₂O. It may further contain nitrogen as well as low levels of noble gases, carbon monoxide, hydrocarbons, depending on the composition of the purge gas, while it is preferred that the combined level of such further components, other than H₂S, CO₂ and H₂O, is less than 10%, more preferably less than 5%. Preferably, the H₂S content of the second product gas is 5-75%, more preferably 10-70%, most preferably 20-60%, based on dry weight of the gas. Likewise, the CO₂ content of the second product gas is preferably below 70%, more preferably below 50%, even more preferably below 40%, based on dry weight of the gas. Most preferably, the CO₂ content is below 30%. Although an as low as possible CO₂ content is preferred, some CO₂ will typically end up in the second product gas, in view of adsorption thereof in step (a) and subsequent desorption in step (b). Thus, the typical CO₂ levels of the second product gas are 2-40%, or 5-35%, or even 10-30%, based on dry weight of the gas. It is especially preferred that the H₂S content is substantially equal or higher than the CO₂ content. The second product gas of the process of the invention has a molar ratio H₂S equivalents to CO₂ of at least 0.25, preferably at least 0.5, up to e.g. 10, most preferably in the range of 0.75-2.

It is further preferred that the combined level of H₂S and CO₂ is between 10 and 95%, more preferably between 20 and 80%, based on dry weight of the gas. Since COS and CS₂ were found to readily adsorb and desorb under the conversion to H₂S and not to revert to COS or CS₂ upon desorption, no or only a negligible amount of COS and CS₂ is observed in the second product gas. Also hardly any or even an untraceable amount of SO_(x) is observed in the second product gas, in view of the presence of a reducing agent, even if the reducing agent is present in the feed gas. Thus, H₂S is the sole sulphur species which is desorbed. The level of any other sulphur species, including COS, CS₂, SO₂, in the second product gas is below 20 ppm, especially below 10 ppm, in particular, the combined levels of all such species is below 20 ppm, in particular less than 10 ppm.

The second product gas, in view of its high H₂S content, is ideally suited to be subjected to further application in e.g. Claus sulphur production. Since Claus tail, appropriately after pre-drying as described further below, gases are especially suitable as feed gas for the process according to the first aspect of the invention, and the second product gas may be recycled to the feed in a Claus process, the present process is particularly suited to be incorporated with a Claus plant. These aspects of the invention are discussed further below. Another advantageous application is the desulphurization of fuel gas in e.g. refineries. The low hydrocarbon content of the second product gas effluent is particularly advantageous, as hydrocarbons are undesirable in the downstream Claus process.

If desired, a flushing (rinsing) step may be inserted between loading step (a) and desorption step (b), so as to avoid mutual contamination of product gases issuing from steps (a) and (b). Such rinsing may be performed using the same temperatures, pressures and flow rates of steps (a) and (b), and may be continued for e.g. between 1 and 15 minutes. Suitable rinsing gases include inert gases, such as nitrogen, and may also contain carbon dioxide, hydrogen or methane, while levels of H₂O should preferably be low (preferably as defined for the feed gas in absolute terms, i.e. below 5%, more preferably below 2%, most preferably below 0.5%) and sulphur compounds should essentially be absent (less than 10 ppm).

After the purging step (b), the adsorbent is typically regenerated so as to allow its reuse in step (a) in the process of the invention. This regeneration includes removal (desorption) of H₂O from the adsorbent, to such an extent that, depending on the water content of the feed gas, the H₂O to H₂S levels during adsorption step (a) are set to the to appropriate conditions as described above. Thus, according to an especially preferred embodiment, the process according to the first aspect of the invention further comprises a step (c) wherein the purged adsorbent is regenerated by drying (i.e. removal of H₂O). The drying of step (c) may be accomplished by any means known in the art for drying a solid adsorbent material. Suitable means include reducing the pressure in the reactor (e.g. pressure swing adsorption (PSA) or vacuum pressure swing adsorption (VPSA) mode), increasing the temperature (e.g. temperature swing adsorption (TSA) mode), contacting the purged adsorbent with dry gas (e.g. passing a gas through the reactor). The dry gas should contain less than 0.1% water, and may comprise nitrogen, noble gases, carbon dioxide, and possibly low levels carbon monoxide and hydrocarbons. Combinations of drying techniques, e.g. depressurisation and heating, may also be used.

The process of the invention is preferably performed in multiple cycles of steps (a)-(c). In other words, the process is performed in cycles of steps (a) to (c). The present process is preferably carried out in cyclic mode. Since contamination of the adsorbent does hardly occur, a large number of cycles, e.g. several thousands or even more, may be performed before any cleaning or exchange of adsorbent or other maintenance steps are needed.

The invention also pertains to the use of an H₂S-enriched gas as obtained in step (b) of the process of the invention as an H₂S feed gas for processes in which appreciable levels, e.g. at least 10% or even at least 25% of H₂S are required. Examples of such process include the production of elemental sulphur, e.g. in the Claus process or in biological partial oxidation (Thiopaq), or for the production of sulphuric acid or other sulphur compounds.

Claus Process

According to a second aspect, the invention concerns a Claus process as known in the art, wherein the process according to the first aspect of the invention is implemented. Claus processes are known in the art and used for desulphurisation of gases, wherein H₂S is converted to elemental sulphur via the overall chemical reaction: 2H₂S+O₂→2S+2H₂O   (3)

This overall reaction may be a combination of several subreactions, which typically occur in several stages of the Claus process. A typical Claus process includes a thermal stage wherein the feed gas comprising H₂S is heated to a temperature above 800° C. by reaction of a sub-stoichiometric amount of oxygen, wherein combustion of H₂S via SO₂ to S, and a catalytic stage, wherein H₂S reacts with SO₂ in the presence of an alumina or titania based catalyst. Side reactions that typically occur during the Claus process include the formation of H₂S, COS, CS₂ and SO₂. These species, together with unreacted H₂S make up the Claus tail gas, which is the major by-product of elemental sulphur produced in the Claus plant. Furthermore, the Claus process can be tuned as known in the art such that SO₂ is typically absent in the Claus tail gas.

Typical Claus feeds include sour natural gas, or more typically the H₂S-enriched stream obtained by amine scrubbing thereof, and gaseous by-products of refineries or other industries. Such gaseous by-products are typically obtained by desulphurization steps, wherein H₂S contaminants are removed from the main product stream, e.g. by amine scrubbers. As such gaseous steams are obtained or formed in large quantities, the Claus process is ubiquitous in present-day industry. To be suitable for conversion by Claus, the feed gas requires a minimum H₂S content of 15%, but at least 25% H₂S is preferred, which renders many H₂S containing gaseous stream unsuitable to be directly used as Claus feed gas. The gases that are suitable as feed gas for the process according to the first aspect of the invention are typical examples of gases that have a too low H₂S content to be suitable as Claus feed gas. However, the second product gas obtained by the process according to the first aspect of the invention contains H₂S in a sufficiently high content to be suitable as feed gas for the Claus process. The process according to the first aspect of the invention can thus be used to enrich a gaseous stream in H₂S in order to make it suitable as feed gas for a Claus process.

The process according to the second aspect of the invention concerns a process for converting H₂S to elemental sulphur (S) comprising the step of subjecting the second product gas as obtained in the process according to the first aspect of the invention, optionally after pre-drying, to a Claus process to obtain elemental sulphur and a tail gas comprising H₂S equivalents and CO₂. If needed, the second product gas is pre-dried, i.e. the H₂O content is reduced, in order to render the second product gas suitable to be subjected to a Claus process. The required composition of the second product gas to be suitable as feed gas for a Claus process depends on whether or not the second product gas is combined with a further feed gas, typically an H₂S-enriched stream obtained by amine scrubbing of sour natural gas or an H₂S-containing gaseous by-product of a refinery or other industry, before or upon being subjected to the Claus process, and to the composition of said further feed gas. The skilled person knows to what extent the second product gas needs to be dried in order to be suitable to be used as feed gas for the Claus process according to the second aspect of the invention. Any means of drying as known in the art may be used as pre-drying, such as cooling and/or pressurisation resulting in condensation of water or by other conventional methods such as absorption or adsorption. Suitable drying means include condensation of steam to liquid water, while keeping H₂S and other species such as CO₂ and inert gases gaseous. The remaining gaseous components are then fed to the Claus process. Cooling of the second product gas from a temperature of about 350° C. to about 40° C. reduces the steam content to about 7%, which is acceptable for a Claus feed gas. In a preferred embodiment, the second product gas is combined with a further feed gas, typically an H₂S-enriched stream obtained by amine scrubbing of sour natural gas or a H₂S-containing gaseous by-product of a refinery or other industry, before or upon being subjected to the Claus process.

In a preferred embodiment, the tail gas of the Claus process according to the second aspect of the invention, comprising H₂S equivalents and CO₂, is used as feed gas in step (a) of the process according to the first aspect of the invention, optionally after pre-drying. In one embodiment, the Claus tail gas is pre-treated prior to being subjected to step (a) of the process according to the first aspect of the invention. Pre-treatment may be employed to lower the H₂O content and/or the SO₂ content (or the SO_(x) content). As the required H₂O content of the feed gas of the process according to the first aspect of the invention is critical, and typical Claus tail gases are too wet, it is preferred that the Claus tail gas is pre-dried, before being subjected as feed gas to the process according to the first aspect of the invention. Any means of drying as known in the art may be used as pre-drying, such as cooling and/or pressurisation resulting in condensation of water or by other conventional methods such as absorption or adsorption. Suitable drying means include condensation of steam to liquid water, while keeping H₂S equivalents and CO₂ gaseous. The remaining gaseous components are then fed to the process according to the first aspect of the invention. Since drier feed gases give rise to increased H₂S adsorption capacity of the adsorbent, it is preferred that pre-treatment to lower the H₂O content includes a measure to lower the H₂O level to well below 1%. Such a measure may include a glycol rinse of the Claus tail gas and/or contacting the Claus tail gas with molecular sieves, optionally after one or more of the above-mentioned techniques. Alternatively or additionally, the H₂O content may be lowered by selective permeation of water through a membrane (e.g. by vacuum permeation). Claus tail gases pre-treated as such are especially suitable to be used as feed gas for the process according to the first aspect of the invention, in view of their extremely low or even negligible water content. Pre-treatment to lower the SO₂ or SO_(x) content is particularly preferred, since the presence of SO₂ is undesirable in the feed gas of the process according to the first aspect of the invention, as discussed above, and typically involves subjecting a SO_(x)-containing gas to a hydrogenation-hydrolysis step, as known to the art, to convert SO_(x) to H₂S. The H₂ required in this respect may originate from the Claus tail gas itself or from substoichiometric combustion of fuel (e.g. natural gas) to a mixture of CO and H₂. SO_(x) can also be lowered by scrubbing with an alkaline solution followed by chemical reduction, e.g. using hydrogen, or by biological reduction, e.g. using bacteria of the genera Desulfovibrio, Desulfobacterium, Desulforomonas or the like. Alternatively and preferably, the Claus process is tuned as known in the art such that the tail gas is substantially free of SO_(x) (i.e. content below 100 ppm, preferably below 10 ppm). Such tuning is typically accomplished by tuning the amount of O₂ added to the Claus feed in the thermal stage, in order to limit the amount SO₂ produced so that the off-gas of the Claus plant does not contain SO₂, but only H₂S (and optionally COS and/or CS₂).

System

In a third aspect, the invention concerns a system designed to implement the processes according to the first and second aspects of the invention, comprising (A) a Claus unit and (B) an adsorption module equipped with (b1) a bed of adsorbent comprising alumina and one or more alkali metals. Any type of Claus unit or even an entire Claus plant as known in the art may be employed as Claus unit (A) in the system according to the invention. Suitable Claus units typically include a thermal unit and a series of catalytic reactors with intermediate cooling units. In the thermal unit, the Claus feed is mixed with a substoichiometric amount of air (or oxygen) and subsequently burnt. Herein, any hydrocarbon present in the Claus feed is preferably combusted and part of the H₂S is converted into SO₂, during which some elemental sulphur is produced. The reaction mixture is transferred to a series of catalytic reactors with intermediate cooling and elemental sulphur condensation stages. Typically, at least two, preferably three or even four catalytic reactors are employed. Each catalytic reactor is employed with a catalyst bed, typically an activated alumina. Herein, the conversion of 2 H₂S and SO₂ into S and 2 H₂O is catalyzed. Since this reaction is an equilibrium reaction, multiple catalytic stages are preferred in order to obtain high yields of elemental sulphur. Remaining hydrocarbons that may still be present in this step may deactivate the catalyst. A standard Claus plant contains three catalytic reactors, which enables sulphur recoveries of 95-98 wt %. Claus unit (A) comprises a first inlet (a1) for receiving a gaseous feed stream and preferably a second inlet (a2) for receiving a further gaseous feed stream. The first inlet (a1) is intended for receiving the second product gas of the process according to the first aspect of the invention, while the optional second inlet (a2) is for receiving an optional further feed gas, as discussed above. Alternatively and preferably, the system according to the invention comprises means (a3) for combing the second product gas and a further feed gas to obtained a combined feed gas prior to the introduction of the combined feed gas into the Claus unit. In this embodiment, first inlet (a1) is intended for receiving the combined gas feed comprising the second product gas of the process according to the first aspect of the invention and the further feed gas. Any means for combining as known in the art can be used as means (a3), such as “in line” or “in pipe” mixing. Typically, the Claus unit comprises a third inlet (a4) for receiving air. The Claus unit further comprises a first outlet (a5) for discharging elemental sulphur (S) and a second outlet (a6) for discharging a tail gas. The Claus unit may comprise further outlets for discharging elemental sulphur and/or tail gas.

The adsorption module (B) comprises at least one bed reactor, wherein the bed (b1) comprises, preferably consists of, the adsorbent according to the invention as bed material. The adsorbent according to the invention comprises alumina and one or more alkali metals and is further described above for the process according to the first aspect of the invention. Adsorption module (B) further comprises a first inlet (b2) for receiving the feed gas and optionally the purging gas, although it is preferred that the purging gas is received via a second inlet (b3), and a first outlet (b4) for discharging the second product gas and optionally the first product gas, although it is preferred that the first product gas is discharged via a second outlet (b5). A single bed reactor may be used, the bed (b1) of which is alternately loaded in step (a), i.e. H₂S equivalents adsorb, and unloaded in step (b), i.e. H₂S desorbs, or two or more reactors in parallel may be used in module (B). Preferably, adsorption module (B) comprises two or more bed reactors, which enables performing step (a) of the process according to the first aspect of the invention in a first reactor and simultaneously step (b) of the process according to the first aspect of the invention in a second reactor. As such, a continuous process is possible, wherein a feed gas may continuously be fed to adsorption module (B), alternating to the first and second reactor, and a purge gas may continuously be fed to adsorption module (B), alternating to the second and first reactor. The reactor to which the feed gas is fed discharges the first product gas, while the reactor to which the purge gas is fed discharges the second product gas. Even more preferred is the use of three bed reactors, wherein a first bed is being subjected to step (a) while a second bed is being subjected to step (b) and a third bed to step (c). In this embodiment, the two, three or more beds operate according to the cyclic scheme of step (a)→step (b)→step (c)→step (a)→etc.

The bed reactor is preferably a packed bed reactor or a fluidized bed reactor, more preferably a packed bed reactor. The reactor is typically in the form of a column, tube or vessel, wherein preferably a reactor is packed with the adsorbent material. The reactor is designed as known in the art, typically to enable the stream of the feed gas or the purge gas, which is introduced via one of the inlets (b2) or (b3), to be led over or through the bed, towards one of the outlets (b4) or (b5). In case a column is used, the inlet (b1) for receiving the feed gas is conveniently placed at the bottom or top of the column, and the outlet (b4) for discharging the product gases is conveniently placed at the other side of the column. Alternative arrangements, including horizontal flows or flow entering and leaving the column at the long sides, are also well suitable.

In the system according to the invention, the Claus unit (A) and the adsorption module (B) are interconnected, i.e. the outlet of one is in fluid connectivity with the inlet of the other, preferably by means of a conduit. As such, the constant flow of (liquid) streams through the system is enabled. Thus, the second outlet (a6) of the Claus unit (A) is in fluid connection with the inlet (b2) of the adsorption module (B), and the first outlet (b4) of the adsorption module (B) is in fluid connection with the first inlet (a1) of the Claus unit (A). Using such arrangement, the Claus tail gas is effectively recycled to the Claus unit by increasing the H₂S content thereof. In view of legal requirements, Claus tail gases need to be treated to remove H₂S equivalents before it may be expelled into the environment after incineration. A major advantage of the recycle according to the present invention is that conventional tail gas treatments (TGT) are no longer required, which are typically less environmentally friendly and more expensive than the process according to the first aspect of the invention. For example, amine scrubbing as TGT removes H₂S together with significant quantities of CO₂, giving a typical ratio of H₂S to CO₂ of below 0.1, which renders this gas less suitable to be recycled to the Claus process. The processes according to the invention are advantageous, since a high quality recycle gases for the Claus unit are obtained. For typical Claus tail-gases having a high CO₂/H₂S ratio, conventional separation technologies are not capable to provide highly enriched H₂S streams. Moreover, conventional TGT usually create a separate sulphur-product such as sulphuric acid. Separation by adsorption gives potentially smaller TGT units compared to conventional TGT units.

In a preferred embodiment, the Claus tail gas as discharged from the Claus unit (A) via outlet (a6) is first led to a steam removal unit (C1) before being received by adsorption module (B) via inlet (b2). Steam removal unit (C1) is thus integrated in the fluid connectivity between outlet (a6) and inlet (b2). Unit (C1) comprises means for removing steam from the Claus tail gas. Any type of such means as known in the art may be used, such as means for cooling and/or pressurisation resulting in condensation of water or other conventional means such as absorption or adsorption means. More preferably, the steam removal means includes a measure to lower the H₂O level to well below 1%. Such a measure may include a glycol rinse of Claus tail feed gas and/or contacting the Claus tail gas with molecular sieves, optionally after one or more of the above-mentioned techniques. Alternatively or additionally, the H₂O content may be lowered by selective permeation of water through a membrane (e.g. by vacuum permeation). Unit (C1) is designed for receiving the Claus tail gas originating from outlet (a6) of Claus unit (A) to the means for steam removal and for discharging the Claus tail gas which is depleted in steam from the means for steam removal. The Claus tail gas depleted in steam is then led to inlet (b2) of adsorption module (B). It is likewise preferred that a similar steam removal unit (C2) is integrated in the fluid connectivity between outlet (b4) and inlet (a1) or, if present, means (a3). Unit (C2) comprises means for removing steam from the second product gas. Any type of such means as known in the art may be used, such as means for cooling and/or pressurisation resulting in condensation of water or other conventional means such as absorption or adsorption means. Unit (C2) is designed for receiving the second product gas originating from outlet (b4) of adsorption module (B) to the means for steam removal and for discharging the second product gas which is depleted in steam from the means for steam removal. The second product gas depleted in steam is then led to inlet (a1) or means (a3) of the Claus unit (A). In the context of the present invention, units (C1) and (C2) are used for pre-drying as described for the processes according to the first and second aspects of the invention.

In a further preferred embodiment, a SO_(x) removal unit is integrated in the fluid connectivity between outlet (b4) and inlet (a1), preferably downstream of the unit C2 if present. The presence of such a SO_(x) removal unit is particularly preferred for Claus tail gases containing SO_(x). The SO_(x) removal unit comprises means for removing SO_(x) from the Claus tail. Suitable means for removing SO_(x) include hydrogenation-hydrolysis means, which is known to the art to covert SO_(x) to H₂S, means for scrubbing with an alkaline solution followed by chemical reduction, e.g. using hydrogen, or means for biological reduction, e.g. using bacteria of the genera Desulfovibrio, Desulfobacterium, Desulforomonas or the like. The SO_(x) removal unit is designed for receiving the Claus tail gas originating from outlet (a6) of Claus unit (A), optionally via unit (C1), to the means for SO_(x) removal and for discharging the Claus tail gas which is depleted in SO_(x) from the means for steam removal. The Claus tail gas depleted in SO_(x) is then led to inlet (b2) of adsorption module (B), optionally via unit (C1).

BRIEF DESCRIPTION OF THE FIGURES

A preferred embodiment of the system according to the invention is depicted in FIG. 1. Claus unit (A) may be any Claus unit or Claus plant as known in the art. It comprises a first inlet (a1) for receiving a combined feed gas originating from means (a3) for combining the second product gas and a further feed gas. Unit (A) further comprises a first outlet (a5) for discharging elemental sulphur and a second outlet (a6) for discharging a Claus tail gas. Second outlet (a6) is in fluid connectivity via steam removal unit (C1) with inlet (b2) of the adsorption module (B). Adsorption module (B) comprises a bed (b1) containing the adsorbent according to the invention as bed material, a first inlet (b2) for receiving the Claus tail originating from unit (C1) and a second inlet (b3) for receiving a purge gas. Module (B) further comprises a first outlet (b4) for discharging the second product gas and a second outlet (b5) for discharging the first product gas. Module (B) is designed as such that incoming gases from inlets (b2) and (b3) are led through or over the bed towards outlets (b4) and (b5). First outlet (b4) is in fluid connectivity via steam removal unit (C2) with means (a3). Means (a3) is designed to combine the second product gas originating from unit (C2) and a further feed gas.

FIGS. 2-8 depict compositions of the tail gases obtained in examples 1-3.

EXAMPLES Example 1

A feed gas containing 10% CO₂, 10% H₂ and 500 ppm H₂S (balanced with N₂) was subjected to adsorption in a packed bed placed in a cylindrical reactor containing 1 g adsorbent. The feed flow was 150 Nml/min, and the bed operated at a temperature of 400° C. and a pressure of 3 bar(a). The process according to the invention was operated in a cyclic co-current mode. Cycles consisted of an adsorption stage, a flushing stage, a purging stage and a regeneration stage. The adsorption stage was continued until full breakthrough of CO₂ and H₂S was reached. Subsequently, the loaded adsorbent was flushed with 10% Ar in N₂ (flow=150 Nml/min) and then purged with a purging gas containing 30% H₂O (balanced with Ar and N₂; flow=150 Nml/min). As last step in the cycle, the adsorbent loaded with H₂O was regenerated by flushing with a dry inert gas (10% Ar in N₂; flow=150 Nml/min). The adsorbents used were K-promoted hydrotalcite MG30 (KMG30), K-promoted alumina (20 wt % K₂CO₂ on alumina) and unpromoted MG30 (control). A similar experiment was conducted with 0.5 g Na-promoted MG30 as adsorbent, which operated at 350° C. and 1 bar(a) and wherein the gas flows (feed, purge and flushes) were 100 Nml/min.

FIGS. 2-5 depict the tail gas (effluent) composition of a cycle of each of the four experiments: FIG. 2 shows the results for KMG30 as adsorbent, FIG. 3 for K-promoted alumina, FIG. 4 for Na-promoted MG30 and FIG. 5 for unpromoted MG30. Ar levels were also determined (data not shown), to visualise the switches between the different stages. These stages are indicated with A, D, F1 and F2, wherein “A” denotes the adsorption stage (feed gas), “D” the desorption or purging stage (purging gas), and “F1” and “F2” the first inert flush and second inert flush (regeneration), respectively. On the y-axis, the mass spectrometer (MS) response in arbitrary units is shown.

In all experiments, fast breakthrough of CO₂ was observed after the adsorption period commenced. Because of the high sorbent capacity for H₂S equivalents, breakthrough of H₂S (and COS) was observed at a later time, indicating saturation of the adsorbent with H₂S and COS at that time. For the control unpromoted adsorbent, breakthrough times for CO₂, H₂S and COS were similar (FIG. 5), indicating that significantly less H₂S (and COS) is adsorbed during the adsorption phase. For the experimental adsorbents, the H₂S+COS slip level before breakthrough as observed in the first effluent (tail gas of the adsorption phase) was less than 5 ppm, i.e. >2 orders of magnitude decrease with respect to the feed gas. It should be noted that no COS was present in the feed gas, meaning that the adsorbent promotes the H₂S+CO₂↔COS+H₂O equilibrium reaction at the operating conditions. In view of the simultaneous breakthrough of H₂S and COS, those species are both adsorbed. Upon steam regeneration, CO₂ was released swiftly from the adsorbent, while desorption of H₂S is spread over a longer period of time. The second effluent (tail gas of the desorption phase) contained H₂S, CO₂, H₂O and inert gases. No desorption of COS was observed, indicating that all adsorbed sulphur species are released as H₂S. For the control unpromoted adsorbent, hardly any H₂S desorption was observed (FIG. 5), reflecting the small amount of H₂S adsorbed in the adsorption period.

Example 2

Two distinct feed gases containing 10% CO₂, 10% H₂ and 500 ppm or 900 ppm H₂S (balanced with N₂) were subjected to adsorption in a packed bed placed in a cylindrical reactor containing 0.5 g K-promoted hydrotalcite MG30 (KMG30) as adsorbent. The feed flow was 200 Nml/min, and the bed operated at a temperature of 350° C. and a pressure of 1 bar(a). The process according to the invention was operated in a cyclic co-current mode. Cycles consisted of an adsorption stage, a flushing stage, a purging stage and a regeneration stage. The adsorption stage was continued until full breakthrough of CO₂ and H₂S was reached. Subsequently, the loaded adsorbent was flushed with 10% Ar in N₂ (flow=200 Nml/min) and then purged with a purging gas containing 30% H₂O (balanced with Ar and N₂; flow=200 Nml/min). As last step in the cycle, the adsorbent loaded with H₂O was regenerated by flushing with a dry inert gas (10% Ar in N₂; flow=200 Nml/min).

FIGS. 6a and 6b depict the tail gas compositions with respect to H₂S and COS for the adsorption stage of a cycle of each of the two experiments: FIG. 6a shows the results for the feed gas comprising 500 ppm H₂S and FIG. 6b for the feed gas comprising 900 ppm H₂S. Levels (in ppm) of H₂S, COS and “total S” (i.e. H₂S+COS) are depicted. The start of breakthrough is observed at about 75 min in FIG. 6a and at about 50 min in FIG. 6b . Before start of breakthrough, the level of total S in the tail gas (slip level) was below 5 ppm. Both H₂S and COS were observed at breakthrough, while only H₂S was fed. At about t=130 min (FIG. 6a ) or t=80 min (FIG. 6b ), the adsorbent reached full capacity for the H₂S equivalents, and full breakthrough was reached.

FIG. 7 depicts a more detailed analysis of the tail gas composition obtained with the feed gas comprising 500 ppm H₂S. Levels (in ppm) of H₂S, COS and “total S” (i.e. H₂S+COS) are depicted. The results of a different cycle as the one presented in FIG. 6a are presented. In the cycle of FIG. 7, the slip level of total S was below 1 ppm (t=840-875 min). At full breakthrough, about 500 ppm of sulphur species (H₂S to COS ratio of about 1) was observed in the tail gas, at which point the loaded adsorbent was briefly flushed (around t=950) and the purging stage commenced. During purging, a peak in the H₂S level of the tail gas was observed, with initial H₂S levels well above 600 ppm, while COS was absent in the tail gas from the start of the purging phase. The second product gas obtained during the purging phase thus contained high levels of H₂S as sole H₂S equivalent.

Example 3

A feed gas containing 10% CO₂, 10% H₂ and 100 ppm CS₂ (balanced with N₂) was subjected to adsorption in a packed bed placed in a cylindrical reactor containing 0.5 g K-promoted hydrotalcite MG30 (KMG30) as adsorbent. The feed flow was 200 Nml/min, and the bed operated at a temperature of 350° C. and a pressure of 1 bar(a). The process according to the invention was operated in a cyclic co-current mode. Cycles consisted of an adsorption stage, a flushing stage, a purging stage and a regeneration stage. The adsorption stage was continued until full breakthrough of CO₂ and H₂S was reached. Subsequently, the loaded adsorbent was flushed with 10% Ar in N₂ (flow=200 Nml/min) and then purged with a purging gas containing 30% H₂O (balanced with Ar and N₂; flow=200 Nml/min). As last step in the cycle, the adsorbent loaded with H₂O was regenerated by flushing with a dry inert gas (10% Ar in N₂; flow=200 Nml/min).

FIG. 8 depicts the tail gas composition with respect to H₂S equivalents for a cycle of the experiment. Levels (in ppm) of H₂S, COS and “total S” (i.e. H₂S+COS+CS₂) are depicted. In the cycle of FIG. 8, the slip level of total S was below 1 ppm (t=24770-24830 min). At full breakthrough, about 200 ppm of sulphur species (H₂S to COS ratio of about 7) was observed in the tail gas, while no CS₂ was completely absent in the tail gas (H₂S+COS=total S). The loaded adsorbent was briefly flushed (around t=24910) and the purging stage commenced. During purging, a peak in the H₂S level of the tail gas was observed, with initial H₂S levels well above 250 ppm, while both COS and CS₂ were completely absent in the tail gas from the start of the purging phase. The second product gas obtained during the purging phase thus contained high levels of H₂S as sole H₂S equivalent, while CS₂ was present as sole H₂S equivalent in the feed gas.

Example 4

Seven distinct feed gases containing 10% CO₂, 10% H₂, and varying amounts of H₂S and H₂O (see Table 2, balanced with N₂) were subjected to adsorption in a packed bed placed in a cylindrical reactor containing 0.5 g K-promoted hydrotalcite MG30 (KMG30) as adsorbent. The feed flow was 200 Nml/min, and the bed operated at a temperature of 350° C. and a pressure of 1 bar(a). The process according to the invention was operated in a cyclic co-current mode. Cycles consisted of an adsorption stage, a flushing stage, a purging stage and a regeneration stage. The adsorption stage was continued until full breakthrough of CO₂ and H₂S was reached. Subsequently, the loaded adsorbent was flushed with 10% Ar in N₂ (flow=200 Nml/min) and then purged with a purging gas containing 30% H₂O (balanced with Ar and N₂; flow=200 Nml/min). As last step in the cycle, the adsorbent loaded with H₂O was regenerated by flushing with a dry inert gas (10% Ar in N₂; flow=200 Nml/min). During cyclic steady state, both the breakthrough adsorption capacity at and the total adsorption capacity of the adsorbent for H₂S equivalents was determined, the results of which are presented in table 2. Breakthrough adsorption capacity refers to the capacity of the adsorbent during the adsorption phase until start of breakthrough, wherein start of breakthrough is defined as the point in time when the total slip level of sulphur species (H₂S+COS) in the tail gas reaches a level of 10 ppm. Total adsorption capacity refers to the capacity of the adsorbent during the adsorption phase until total breakthrough is reached, i.e. when the content of sulphur species (H₂S+COS) in the tail gas is equal to the content of sulphur species in the feed gas.

TABLE 2 Feed gas compositions and adsorption capacities for H₂S Feed gas composition (ppm) Adsorption capacity (mol/kg) Entry H₂S H₂O H₂O/H₂S breakthrough total 1 500 0 0 0.57 0.841 2 500 575 1.15 0.40 0.727 3 500 900 1.80 0.31 0.617 4 900 0 0 0.62 1.124 5 900 750 0.83 0.50 1.053 6 900 2100 2.33 0.33 0.816 7 25000 117000 4.68 n.d. 0.14

For both the feed gases comprising 500 ppm H₂S and the feed gases comprising 900 ppm H₂S, the adsorption capacity of the adsorbent decreased with increasing H₂O content of the feed gas. The adsorption capacity for H₂S decreased by about a factor 2 when the H₂O/H₂S ratio increased to above 2. Extrapolating the results in Table 2, the adsorption capacity for H₂S decreased to unacceptable levels in case the H₂O/H₂S ratio increases to above 5, while the best results are obtained with a H₂O/H₂S ratio of at most 2. It should be noted that since only H₂S was used as H₂S equivalent, X amounts to zero for the feed gases tested here. 

The invention claimed is:
 1. A process for altering the composition of a gas comprising H₂S equivalents and CO2, comprising the steps of: (a) contacting a feed gas containing H₂S equivalents, CO₂ and optionally H₂O, wherein the molar ratio of H₂O to H₂S equivalents is within the range of 0-(5+X), with a solid adsorbent at a temperature of 250-500° C., to obtain a loaded adsorbent and a first product gas; (b) contacting the loaded adsorbent with a purge gas containing H₂O, to obtain a second product gas; and (c) regenerating the adsorbent after step (b) by removal of H₂O, wherein the process is performed in cycles of steps (a) to (c), and wherein the feed gas and/or the purge gas contains a reducing agent and the adsorbent comprises alumina and one or more alkali metals, and wherein X is defined as: $X = {\sum\frac{n_{i} \times \left\lbrack {H_{2}S\mspace{14mu}{equivalent}} \right\rbrack_{i}}{\left\lbrack {H_{2}S{\mspace{11mu}\;}{equivalents}} \right\rbrack}}$ wherein [H₂S equivalents] indicates the total concentration of H₂S equivalents, [H₂S equivalent]_(i) indicates the concentration of a particular H₂S equivalent i and n_(i) indicates the amount of water molecules n consumed when said H₂S equivalent i is converted to H₂S.
 2. The process according to claim 1, wherein the H₂S equivalents comprise H₂S, COS and/or CS₂.
 3. The process according to claim 1, wherein the molar ratio of H₂S equivalents to CO₂ in the feed gas is below
 1. 4. The process according to claim 1, wherein the molar ratio of H₂S equivalents to CO₂ in the feed gas is in the range of 0.001-0.1.
 5. The process according to claim 1, wherein the feed gas contains 0.1-20% H₂ as the reducing agent.
 6. The process according to claim 1, wherein the adsorbent further comprises one or more divalent metals.
 7. The process according to claim 1, wherein the divalent metals are oxides, hydroxides, carbonates, sulphides and/or hydrosulphides.
 8. The process according to claim 1, wherein the adsorbent further comprises MgO.
 9. The process according to claim 5, wherein the alkali metal is K and the adsorbent is K-promoted alumina, or is based on a K-promoted hydrotalcite.
 10. The process according to claim 1, wherein the process is continued with step (a) after the regeneration of step (c).
 11. The process according to claim 1, wherein step (b) is performed counter-currently with respect to step (a).
 12. The process according to claim 1, wherein the purge gas comprises at least 75% H₂O.
 13. The process according to claim 1, wherein the first product gas contains less than 10 ppm of H₂S equivalents, and/or the first product gas contains less than 0.1 times the level of H₂S equivalents of the feed gas, and/or the first product gas has a molar ratio of H₂S equivalents to CO₂ of less than 0.005.
 14. The process according to claim 1, wherein the second product gas has a molar ratio of H₂S equivalents to CO₂ of at least 0.5.
 15. The process according to claim 1, wherein the feed gas is an optionally pre-dried syngas further containing H₂ and CO.
 16. The process according to claim 1, wherein the feed gas is an optionally pre-treated Claus tail gas further containing N₂.
 17. The process according to claim 1, wherein the second product gas is subjected, optionally after pre-drying, to a Claus process to obtain elemental sulphur and a tail gas comprising H₂S equivalents and CO₂, and the tail gas is used as feed gas in step (a), optionally after pre-drying.
 18. A method for the production of elemental sulphur comprising subjecting a H₂S-enriched gas to a Claus process, wherein the H₂S-enriched gas is obtained in step (b) of a process for altering the composition of a gas comprising H₂S equivalents and CO₂, comprising the steps of: (a) contacting a feed gas containing H₂S equivalents, CO₂ and optionally H₂O, wherein the molar ratio of H₂O to H₂S equivalents is within the range of 0-(5+X), with a solid adsorbent at a temperature of 250-500° C., to obtain a loaded adsorbent and a first product gas; (b) contacting the loaded adsorbent with a purge gas containing H₂O, to obtain a second product gas; and (c) regenerating the adsorbent after step (b) by removal of H₂O, wherein the process is performed in cycles of steps (a) to (c), and wherein the feed gas and/or the purge gas contains a reducing agent and the adsorbent comprises alumina and one or more alkali metals, and wherein X is defined as: $X = {\sum\frac{n_{i} \times \left\lbrack {H_{2}S\mspace{14mu}{equivalent}} \right\rbrack_{i}}{\left\lbrack {H_{2}S{\mspace{11mu}\;}{equivalents}} \right\rbrack}}$ wherein [H₂S equivalents] indicates the total concentration of H₂S equivalents, [H₂S equivalent]_(i) indicates the concentration of a particular H₂S equivalent i and n_(i) indicates the amount of water molecules n consumed when said H₂S equivalent i is converted to H₂S.
 19. The process according to claim 3, wherein the molar ratio of H₂S equivalents to CO₂ in the feed gas is in the range of 0.001-0.1.
 20. The process according to claim 6, wherein the divalent metals are in the form of oxides, hydroxides, carbonates, sulphides and/or hydrosulphides.
 21. The process according to claim 20, wherein the adsorbent further comprises MgO. 